The demand for electricity continues to grow globally. In order to keep stride with the growing demand, coal is being looked to as a source for its generation. At present, burning coal produces some 50% of the electricity generated in the United States. The burning of coal in power generation plants results in the release of energy, as well as the production of solid waste such as bottom and fly ash, and flue gas emissions into the environment. Emissions Standards, as articulated in The Clean Air Act Amendments of 1990 as established by the U.S. Environmental Protection Agency (EPA), requires the assessment of hazardous air pollutants from utility power plants.
The primary gas emissions are criteria pollutants (e.g. sulfur dioxide, nitrogen dioxides, particulate material, and carbon monoxide). About two thirds of all sulfur dioxide and a quarter of the nitrogen dioxide in the atmosphere is attributable to electric power generation achieved by burning coal and other fuels.
Secondary emissions depend on the type of coal or fuel being combusted but include as examples mercury, selenium, arsenic, and boron. Coal-fired utility boilers are known to be a major source of anthropogenic mercury emissions in the United States. In December of 2000, the EPA announced their intention to regulate mercury emissions from coal-fired utility boilers despite the fact that a proven best available technology (BAT) did not exist to capture or control the levels of mercury released by the combustion of coal. This has been further complicated by the lack of quick, reliable, continuous monitoring methods for mercury.
The fact remains that mercury is found in coals at concentrations ranging from 0.02 to 1 ppm. The mercury is present as sulfides, or associated with organic matter. Upon combustion the mercury is released and emitted into the flue gas as gaseous elemental mercury and other mercury compounds. The mercury appears in the flue gas in both the solid and gas phases (particulate-bound mercury and vapor-phase mercury, respectively). The so-called solid phase mercury is really vapor-phase mercury adsorbed onto the surface of ash and/or carbon particles. The solid-phase mercury can be captured by existing particle control devices (PCDs) such as electrostatic precipitators (ESPs) and fabric filters (FF), the latter is sometimes referred to as baghouses.
A review of data collected by the EPA in 1999 under the Mercury Information Collection Request (ICR) showed that PCDs alone could capture from 20 to 42% of the total mercury in the fuel. Of course, the efficiency of this strategy depends on the fuel composition, the operating temperature and design of the PCD. Indeed, it has been found that fabric filters tend to exhibit better particulate laden mercury removal, compared to cold-side ESPs, as a result of the formation of filter cake within the filter. The filter cake contains constituents that absorb and/or adsorb mercury such as unreacted carbon, activated carbon, iron, and fly ash. As such the filter cake can act as a site to facilitate gas-solid reactions between the vapor-phase mercury and the trapped solid particulate. The data suggests FFs can currently achieve as much as 82% mercury capture.
The volatility of mercury and many of its compounds results in a significant portion of the total mercury existing as vapor-phase mercury in the flue gases. Vapor-phase mercury is composed of elemental mercury and oxidized mercury, the relative amounts of these forms being dependent on the amount of chloride in the coal, iron oxide levels in the coal and other constituents in the fly ash as examples. Speciation, which refers to the form of vapor-phase mercury, is a key parameter in development and design of capture strategies for mercury emissions. Generally there are two forms of mercury that constitute vapor-phase mercury. The forms are oxidized (Hg2+ as an example) and elemental (Hg0) mercury.
Several control strategies have been developed for the control of mercury emissions from coal-fired boilers. Some of these methods include injection of activated carbon, modified activated carbon, various chemical catalysts, and inorganic sorbents. Unfortunately, none of these strategies removes all the mercury from the flue gas. The efficiencies range from as low as 30% to as high as 80% based on the amount of mercury entering the system with the coal. In addition, these technologies either produce unwanted effects on by-products such as impacting the quality of fly ash, or generate additional waste streams for the power plant. Both lead to higher operational costs for the power plant. One promising strategy is to take advantage of existing air pollution control devices or APCDs to augment or to serve as the primary means to remove vapor-phase mercury. Two examples of APCDs are semi-dry and wet scrubbers or Flue Gas Desulfurizer (FGD). Semi-dry FGDs are also known as Spray Dryer Absorbers or SDAs.
Sulfur oxides (SOx) regulatory compliance mandates the use of at least one of several control strategies. Three such strategies that are used in the US are sorbent injection into the boiler during coal burning and wet or dry Flue Gas Desulfurizers. At present about 3% of the coal-fired power plants are using sorbent injection. FGD scrubbing accounts for 85% using wet and 12% using dry scrubber technologies. Wet scrubbers achieve greater than 90% SOx removal efficiency compared to 80% by dry scrubbing. In wet scrubbers, the flue gas is brought into contact with slurry containing an alkaline calcium mineral, such as lime or limestone. The SOx is adsorbed into the water and reacts to form calcium sulfite. It has been demonstrated that simultaneous to SOx capture, wet FGDs can be used to capture vapor-phase mercury from the flue gas.
Elemental mercury is water insoluble and is not removed by a wet FGD. In contrast, oxidized mercury in the flue gas is water-soluble and is removed. The ICR mercury data demonstrated that ionic mercury is removed effectively approaching 90% by wet FGDs. Hence, one strategy for mercury capture is to oxidize all the mercury during the burning of the coal and capture the oxidized mercury in the wet scrubber. Work carried out by URS in conjunction with DOE/NETL has been investigating just such a strategy. There are two critical technical steps to the implementation of this strategy. The first is the complete oxidation of the vapor-phase mercury exiting the boiler and the coal. URS, among others, is developing strategies and technologies to accomplish this step. To date, they have demonstrated that independent of the coal type, vapor-phase mercury speciation can be shifted to extensively 100% oxidized mercury. The second critical technical step in the implementation of this control strategy is the sorption of the oxidized mercury and removal in the wet scrubber. The problem, identified early on, is that there are reactions occurring in the wet scrubber liquor that reduce oxidized mercury to elemental mercury and lead to “re-emission” or release of elemental mercury into the scrubbed flue gas. The prevention of reduction of ionic mercury in wet scrubber liquor has been studied and reported on by G. M. Blythe and D. W. DeBerry at URS and others.
The findings have suggested that complexation of the ionic mercury is one way to reduce or eliminate the generation of elemental mercury in the scrubber. This same study has demonstrated that not all chelants of ionic mercury can accomplish this in a wet FGD. In a recent presentation, plant results of such a chelant, TMT-15, trimercapto-s-triazine, available from Degussa, were inconclusive regarding the prevention of re-emission of mercury across a wet scrubber. The invention is illustrated by the proceeding descriptions and the following examples which are not meant to limit the invention unless otherwise stated in the claims appended hereto.
Consequently, there remains a need for a technology that can cost-effectively prevent the reduction of ionic mercury in wet scrubbers. The invention described below addresses this need.